Hydraulic fracturing of petroleum recovery wells enhances the extraction of fluids from low permeability formations due to the high permeability of the induced fracture and the size and extent of the fracture. A single hydraulic fracture from a well bore results in increased yield of extracted fluids from the formation. Hydraulic fracturing of highly permeable unconsolidated formations has enabled higher yield of extracted fluids from the formation and also reduced the inflow of formation sediments into the well bore. Typically the well casing is cemented into the borehole, and the casing perforated with shots of generally 0.5 inches in diameter over the depth interval to be fractured. The formation is hydraulically fractured by injecting the fracturing fluid into the casing, through the perforations, and into the formation. The hydraulic connectivity of the hydraulic fracture or fractures formed in the formation may be poorly connected to the well bore due to restrictions and damage due to the perforations. Creating a hydraulic fracture in the formation that is well connected hydraulically to the well bore will increase the yield from the well, result in less inflow of formation sediments into the well bore and result in greater recovery of the petroleum reserves from the formation.
Turning now to the prior art, hydraulic fracturing of subsurface earth formations to stimulate production of hydrocarbon fluids from subterranean formations has been carried out in many parts of the world for over fifty years. The earth is hydraulically fractured either through perforations in a cased well bore or in an isolated section of an open bore hole. The horizontal and vertical orientation of the hydraulic fracture is controlled by the compressive stress regime in the earth and the fabric of the formation. It is well known in the art of rock mechanics that a fracture will occur in a plane perpendicular to the direction of the minimum stress, see U.S. Pat. No. 4,271,696 to Wood. At significant depth, one of the horizontal stresses is generally at a minimum, resulting in a vertical fracture formed by the hydraulic fracturing process. It is also well known in the art that the azimuth of the vertical fracture is controlled by the orientation of the minimum horizontal stress in consolidated sediments and brittle rocks.
At shallow depths, the horizontal stresses could be less or greater than the vertical overburden stress. If the horizontal stresses are less than the vertical overburden stress, then vertical fractures will be produced; whereas if the horizontal stresses are greater than the vertical overburden stress, then a horizontal fracture will be formed by the hydraulic fracturing process.
Techniques to induce a preferred horizontal orientation of the fracture from a well bore are well known. These techniques include slotting, by either a gaseous or liquid jet under pressure, to form a horizontal notch in an open bore hole. Such techniques are commonly used in the petroleum and environmental industry. The slotting technique performs satisfactorily in producing a horizontal fracture, provided that the horizontal stresses are greater than the vertical overburden stress, or the earth formation has sufficient horizontal layering or fabric to ensure that the fracture continues propagating in the horizontal plane. Perforations in a horizontal plane to induce a horizontal fracture from a cased well bore have been disclosed, but such perforations do not preferentially induce horizontal fractures in formations of low horizontal stress. See U.S. Pat. No. 5,002,431 to Heymans.
Various means for creating vertical slots in a cased or uncased well bore have been disclosed. The prior art recognizes that a chain saw can be used for slotting the casing. See U.S. Pat. No. 1,789,993 to Switzer; U.S. Pat. No. 2,178,554 to Bowie, et al., U.S. Pat. No. 3,225,828 to Wisenbaker, U.S. Pat. No. 4,119,151 to Smith, U.S. Pat. No. 5,335,724 to Venditto et al.; U.S. Pat. No. 5,372,195 to Swanson et al.; and U.S. Pat. No. 5,472,049 to Chaffee et al. Installing pre-slotted or weakened casing has also been disclosed in the prior art as an alternative to perforating the casing, because such perforations can result in a reduced hydraulic connection of the formation to the well bore due to pore collapse of the formation surrounding the perforation. See U.S. Pat. No. 5,103,911 to Heijnen. These methods in the prior art were not concerned with the initiation and propagation of the hydraulic fracture from the well bore in an unconsolidated or weakly cemented sediment. These methods were an alternative to perforating the casing to achieve better connection between the well bore and the surrounding formation and/or initiate the fracture at a particular location and/or orientation in the subsurface.
In the art of hydraulic fracturing subsurface earth formations from subterranean wells at depth, it is well known that the earth's compressive stresses at the region of fluid injection into the formation will typically result in the creation of a vertical two “winged” structure. This “winged” structure generally extends laterally from the well bore in opposite directions and in a plane generally normal to the minimum in situ horizontal compressive stress. This type of fracture is well known in the petroleum industry as that which occurs when a pressurized fracture fluid, usually a mixture of water and a gelling agent together with certain proppant material, is injected into the formation from a well bore which is either cased or uncased. Such fractures extend radially as well as vertically until the fracture encounters a zone or layer of earth material which is at a higher compressive stress or is significantly strong to inhibit further fracture propagation without increased injection pressure.
It is also well known in the prior art that the azimuth of the vertical hydraulic fracture is controlled by the stress regime with the azimuth of the vertical hydraulic fracture being perpendicular to the minimum horizontal stress direction. Attempts to initiate and propagate a vertical hydraulic fracture at a preferred azimuth orientation have not been successful, and it is widely believed that the azimuth of a vertical hydraulic fracture can only be varied by changes in the earth's stress regime. Such alteration of the earth's local stress regime has been observed in petroleum reservoirs subject to significant injection pressure and during the withdrawal of fluids resulting in local azimuth changes of vertical hydraulic fractures.
Hydraulic fracturing generally consists of two types, propped and unpropped fracturing. Unpropped fracturing consists of acid fracturing in carbonate formations and water or low viscosity water slick fracturing for enhanced gas production in tight formations. Propped fracturing of low permeability rock formations enhances the formation permeability for ease of extracting petroleum hydrocarbons from the formation. Propped fracturing of highly permeable formations is for sand control, i.e. to reduce the inflow of sand into the well bore, by placing a highly permeable propped fracture in the formation and pumping from the fracture, thus reducing the pressure gradients and fluid velocities due to draw down of fluids from the well bore. Hydraulic fracturing involves the literal breaking or fracturing of the rock by injecting a specialized fluid into the well bore passage through perforations in the casing to the geological formation at pressures sufficient to initiate and/or extend the fracture in the formation. The theory of hydraulic fracturing utilizes linear elasticity and brittle failure theories to explain and quantify the hydraulic fracturing process. Such theories and models are highly developed and generally sufficient for the art of initiating and propagating hydraulic fractures in brittle materials such as rock, but are totally inadequate in the understanding and art of initiating and propagating hydraulic fractures in ductile materials such as unconsolidated sands and weakly cemented formations.
Hydraulic fracturing has evolved into a highly complex process with specialized fluids, equipment, and monitoring systems. The fluids used in hydraulic fracturing vary depending on the application and can be water, oil, or multi-phase based. Aqueous based fracturing fluids consist of a polymeric gelling agent such as solvatable (or hydratable) polysaccharide, e.g. galactomannan gums, glycomannan gums, and cellulose derivatives. The purpose of the hydratable polysaccharides is to thicken the aqueous solution and thus act as viscosifiers, i.e. increase the viscosity by 100 times or more over the base aqueous solution. A cross-linking agent can be added which further increases the viscosity of the solution. The borate ion has been used extensively as a cross-linking agent for hydrated guar gums and other galactomannans, see U.S. Pat. No. 3,059,909 to Wise. Other suitable cross-linking agents are chromium, iron, aluminum, zirconium (see U.S. Pat. No. 3,301,723 to Chrisp), and titanium (see U.S. Pat. No. 3,888,312 to Tiner et al). A breaker is added to the solution to controllably degrade the viscous fracturing fluid. Common breakers are enzymes and catalyzed oxidizer breaker systems, with weak organic acids sometimes used.
Oil based fracturing fluids are generally based on a gel formed as a reaction product of aluminum phosphate ester and a base, typically sodium aluminate. The reaction of the ester and base creates a solution that yields high viscosity in diesels or moderate to high API gravity hydrocarbons. Gelled hydrocarbons are advantageous in water sensitive oil producing formations to avoid formation damage, that would otherwise be caused by water based fracturing fluids.
Foam based fracturing fluids consist of a liquid phase viscosifier, being a polymeric gelling agent such as solvatable (or hydratable) polysaccharide, e.g. galactomannan gums, glycomannan gums, and cellulose derivatives, surfactants, gaseous phase generally being nitrogen N2 or carbon dioxide CO2 or a combination of N2 and CO2, breakers, foaming agent and a clay stabilizer, typically potassium chloride KCl. In certain cases methanol is added to enhance foam stability and in certain cases the liquid phase polymer viscosifier is substituted by a non-polymer surfactant. Foam fluid functional properties, such as proppant carrying capacity, resistance to leakoff, and viscosity for fracture width creation, are derived from the foam structure and the liquid phase properties. Foam structure is preserved by the formation of stable interfacial surfaces that basically entrain the liquid and gaseous phases within the foam structure. This foam structure breaks down over time and thus it is important to design the foam to be stable during the fracturing process. Foams used as hydraulic fracturing fluids can vary considerably in quality, texture and rheology depending on the application in hand, but all foams have certain stability properties that entrain the liquids and gaseous phases within its structure, albeit for a wide range of half lives.
Leak off of the fracturing fluid into the formation during the injection process has been conceptually separated into two types, spurt and linear or Carter leak off. Spurt occurs at the tip of the fracture and is the fracturing fluid lost to the formation in this zone. In highly permeable formations spurt leak off can be a large portion of the total leak off. Carter leak off occurs along the fracture length as the fracture is propagated. Laboratory methods are used to quantify a fracturing fluid's leak off performance; however, analyses of actual field data on hydraulic fracturing of a formation is required to quantify the leak off parameters in situ, see U.S. Pat. No. 6,076,046 to Vasudevan et al.
The method of controlling the azimuth of a vertical hydraulic fracture in formations of unconsolidated or weakly cemented soils and sediments by slotting the well bore or installing a pre-slotted or weakened casing at a predetermined azimuth has been disclosed. The method disclosed that a vertical hydraulic fracture can be propagated at a pre-determined azimuth in unconsolidated or weakly cemented sediments and that multiple oriented vertical hydraulic fractures at differing azimuths from a single well bore can be initiated and propagated for the enhancement of petroleum fluid production from the formation. See U.S. Pat. No. 6,216,783 to Hocking et al, U.S. Pat. No. 6,443,227 to Hocking et al, U.S. Pat. No. 6,991,037 to Hocking, U.S. Pat. No. 7,748,458, U.S. patent application Ser. No. 11/277,308, filed Mar. 23, 2006, and U.S. Pat. No. 7,404,441, filed Mar. 12, 2007. The method disclosed that a vertical hydraulic fracture can be propagated at a pre-determined azimuth in unconsolidated or weakly cemented sediments and that multiple orientated vertical hydraulic fractures at differing azimuths from a single well bore can be initiated and propagated for the enhancement of petroleum fluid production from the formation.
The pumping rate of the fracturing fluid and the viscosity of the liquid phase fracturing fluids needs to be controlled, as described by Hocking (U.S. patent application Ser. No. 11/277,308, filed Mar. 23, 2006, and U.S. Pat. No. 7,404,441, filed Mar. 12, 2007) to initiate and propagate the fracture in a controlled manner in weakly cemented sediments. The dilation of the casing and grout imposes a dilation of the formation that generates an unloading zone in the formation, and such dilation of the formation reduces the pore pressure in the formation in front of the fracturing tip. It has been disclosed that laboratory and field experiments of hydraulic fracture initiation and propagation in weakly cemented sediments have quantified that without dilation of the formation in a direction orthogonal to the plane of the intended fracture, chaotic and/or multiple fractures and/or cavity expansion/formation compaction zones are created rather than a single orientated fracture in a preferred azimuth direction irrespective of the pumping rate of the hydraulic fluid during attempted initiation of the fracture. Similar laboratory and field experiments of hydraulic fracture initiation and propagation in weakly cemented sediments have quantified that with dilation of the formation in a direction orthogonal to the plane of the intended fracture, if the pumping rate of the hydraulic fluid during attempted initiation of the fracture is not limited then chaotic and/or multiple fractures and/or cavity expansion/formation compaction zones are created rather than a single orientated fracture in a preferred azimuth direction. To ensure a repeatable single orientated hydraulic fracture is formed, the formation needs to be dilated orthogonal to the intended fracture plane, the liquid phase fracturing fluid pumping rate needs to be limited to avoid over-running the liquefied zone in front of the fracture tip and the viscosity of the liquid phase fracturing fluid has to be such so as not to negate the pore pressure gradients in front of the fracture tip.
In foam based fracturing fluids, the liquid and gaseous phases are entrained within the foam structure, and whilst the foam is in a stable state, these fluids do not separate from the foam under fracturing pumping pressures. Thus, liquids from the foam fracturing fluid cannot flow into the zone in front of the fracture tip, and due to the foam compressibility, cannot result in over-running the liquefied zone in front of the fracture. Therefore, by using foam fracturing fluids in weakly cemented formations, one will ensure that a stable repeatable orientated fracture can be initiated and propagated within these formations.
Accordingly, there is a need for a method and apparatus for controlling the initiation and propagation of a hydraulic fracture using foam based fracturing fluids in a single well bore in formations of unconsolidated or weakly cemented sediments, which behave substantially different from brittle rocks in which most of the hydraulic fracturing experience is founded. Also, there is a need for a method and apparatus that hydraulically connects the installed hydraulic fractures to the well bore without the need to perforate the casing.